1. Field of the Invention
This invention relates to the control of slugging in a line, such as severe slugging that may occur in a riser that transports production fluid from a hydrocarbon well at a seafloor to a topside facility at the sea surface.
2. Description of Related Art
Risers are commonly used in offshore piping in the hydrocarbon industry to transport production fluids from a wellhead on the seafloor to a facility at the sea surface, such as a topside separator and process facility on an offshore platform. The production fluid provided from the well and transported through the riser is often a multiphase fluid, e.g., a mixture of liquid(s) and gas(es), such as a mixture of oil, water, and natural gas. The presence of gas in the fluid can assist in lifting the fluid through the riser by reducing the hydrostatic head of liquid in the riser. Conversely, the absence of gas in the riser results in larger hydrostatic pressure and increase in the back pressure on the well. Therefore, it is generally desirable to avoid impeding the flow of gas to the riser.
An unstable phenomenon referred to as “slugging” can occur in an offshore riser when liquid flowing into the riser blocks the pipe and the hydrostatic head at the blockage temporarily builds up faster in the riser than the pressure in the trapped gas upstream of the riser. For example, FIG. 1 illustrates a production line 2 that transports production fluid to a riser 4. The production line 2 is located on the seafloor 6 and ramps slightly downward toward the riser 4, and the riser 4 extends upwards from the seafloor 6 to a facility 8 at the sea surface 10. The production line 2 and riser 4 define an angle, or pinch point 12, at the connection thereof. As shown in FIG. 1, a slug of liquid 14 has formed at the pinch point 12 and blocks the riser 4 such that gas in the production line 2 cannot flow into the riser 4. Gas in the production line 2 upstream of the pinch point 14 builds in pressure until the pressure of the gas exceeds the hydrostatic head of the liquid, and the gas then proceeds into the riser 4, moving the liquid slug 14 upward through the riser 4 and out of the riser 4 into the topside facility 8. The pressure in the fluid provided to the facility 8 can vary widely, typically decreasing as the liquid level builds and then rising quickly as the slug 14 is subsequently transported through the riser 4 to the facility 8.
The term “severe slugging” refers to an extreme type of unstable slugging, in which the liquid slug 14 fills the entire riser 4. When severe slugging occurs, the upstream gas pressure must build to a sufficient level to overcome the hydrostatic head of the liquid filling the riser 4. If the riser 4 extends upward by a great vertical distance, e.g; from seafloor to sea surface, the hydrostatic head associated with severe slugging can be significant. Severe slugging is referred to as “ultra-severe slugging” when the liquid slug blockage occurs in an upward incline of piping that is upstream of the riser, such that the riser and a length of piping upstream of the riser, sometimes miles of piping, fill with liquid before the gas pressure becomes sufficient great to overcome the hydrostatic head of the liquid and move the liquid through the riser.
The instantaneous flow rates of alternating gas and liquid in a severe slugging cycle can be much higher, in some cases more than an order of magnitude higher, than the average flow rates of the fluid through the riser. The large changes in flow rates can cause severe changes in the liquid level in the primary separator, or other facility fed by the riser 4, and can interfere with proper separation and fluid processing in the facility. In addition, the large pressure changes with the fluid provided to the facility can be detrimental to equipment and the production operation.
A variety of systems and methods have been proposed for controlling or otherwise dealing with slugging. For example, the following methods are used in some conventional systems: (1) increasing the size of a primary separator that receives the production fluid from the riser so that the separator can handle the slugs, (2) increasing the back pressure on the riser with a topside control valve, (3) implementing a pressure control strategy via the topside automatic control valve, (4) using various combinations of the foregoing methods, (5) increasing the pressure at the riser, e.g., by employing a downhole pump in the well, (6) increasing the gas flow rate in the riser, e.g., by adding or increasing the gas in the riser or well, or (7) separating the gas and liquid at the base of the riser and allowing the gas to rise through a first riser while pumping the liquid to the surface in a separate, second riser.
While the foregoing methods can be useful for reducing the effects of slugging, each of the methods generally raises additional concerns and/or costs. For example, increasing the size of the separator can reduce some slugging; however, for increasingly deep and long risers, the size increases that are required for the separator can become impractical. The methods (2)-(5) above generally reduce the compressibility of the gas by increasing the pressure at the riser which, in turn, increases the rate at which gas pressure can build and overcome the hydrostatic head build up. Methods (2)-(4) above often result in increased backpressure and an unacceptable loss of production. Methods (5)-(7) above require the addition of energy and/or to the system and, consequently, depend upon the availability of sufficient power and/or gas.
Thus, a continued need exists for an improved system and method for slug control. The system and method should be capable of using the gas in the production fluid to provide at least some of the lift force required for transporting the fluid through the riser, and the system and method should be compatible with risers extending to great depths or lengths.